Reservoir Characterization 4:
`4-D Seismology Case Studies
`
`Thursday a.m., Nov. 6
`
`R C 4 . 1
`
`Time-lapse seismic analysis of the North Sea Fulmar Field
`David H. Johnston*, Robert S. McKenny, Exxon Production Research Co., and Tucker D. Burkhart, Pennsylvania
`State University
`
`Summary
`
`Time-lapse seismic analysis has been applied to two 3-D
`seismic surveys acquired over the Central North Sea Ful-
`mar Field -- a pre-production survey shot in 1977,
`reprocessed in 1987, and a 1992 survey. The Upper Juras-
`sic reservoirs in the field have been under production since
`1982. Water is the main drive mechanism, supported by
`flank injection. Although the field is currently at over 80%
`water cut, there are infill opportunities.
`Petrophysical
`analyses for Fulmar indicate that water replacing oil will
`result in an increase in seismic impedance. In addition, a
`pressure decline of about 1000 psi during the time between
`the two seismic surveys will result in a further impedance
`increase. These impedance changes are observed between
`the two seismic surveys.
`In order to overcome inherent
`differences in the seismic data due to acquisition and proc-
`essing differences, the data are equalized and then inverted
`to obtain impedance which is then averaged between the
`top of the reservoir and the position of the original oil-
`water contact. Differences in averaged impedance between
`the 1977 and 1992 surveys clearly show the effects of wa-
`ter influx and pressure decline. The changes observed in
`the seismic data are overall consistent with predictions
`obtained from a full-field, history-matched flow simula-
`tion. Differences in details may suggest areas of bypassed
`oil. However, data quality is not sufficient to serve as the
`sole basis for drilling decisions.
`
`Introduction
`
`In the later phases of a field’s life, reservoir surveillance is
`a key to meeting goals of reduced operating costs and
`maximized recovery. Differences between actual and pre-
`dicted performance are typically used to update the
`geological model of the reservoir and to revise the deple-
`tion strategy. The changes in reservoir fluid saturation,
`pressure, and temperature that occur during production also
`induce changes in the reservoir acoustic properties of rocks
`that may be detected by seismic methods under favorable
`conditions.
`
`The key to seismic surveillance is the concept of differen-
`tial imaging using time-lapse measurements. While one
`seismic image of a reservoir may not show any obvious
`production-related effects, differences in repeated surveys
`may be able to detect even subtle changes in reservoir
`
`properties. Acquisition of a seismic survey before produc-
`tion or intervention establishes the baseline conditions of
`the reservoir. Subsequent monitor surveys are differenced
`from the base survey. The result is a seismic difference
`volume which, when integrated with reservoir characteri-
`zation and flow simulation, may be used to track the
`movement of fluid in a reservoir between well control.
`
`However, the difference between two seismic surveys is
`not only sensitive to changes in reservoir rock properties
`but is also sensitive to differences in acquisition and proc-
`essing,
`and errors in navigation.
`As a result, the
`repeatability of seismic data is a key issue. For legacy
`seismic data, differencing the horizon-keyed average of
`attributes such as impedance is more robust in the presence
`of noise and data artifacts.
`
`The Fulmar Field
`
`The Fulmar Field lies in the Central North Sea approxi-
`mately 270 km southeast of Aberdeen. The field was
`discovered in 1975 and is between 9900 and 11000 feet
`TVSS. It consists of an eroded triangular anticline (Figure
`1) with a relatively small area1 extent. Oil is found in two
`Upper Jurrasic reservoirs, the shallow marine sandstones of
`the Fulmar Formation, containing over 90% of the re-
`serves, and the overlying deep-marine turbidite Ribble
`sand. The Fulmar formation is as thick as 1200 feet with
`an original oil column greater than 900 feet. The sands are
`well sorted and fine-to-medium grained with excellent
`reservoir properties. The average porosity is 23.4% and
`permeabilities range from 500 to 4000 mD. The Ribble
`has porosities of 30% and permeabilities from 1000 to
`4000 mD. Field OOIP volume is roughly 853 MBO (40
`degree API and 614 scf/stb GOR).
`
`Water is the main drive mechanism but limited acquifer
`support has required downflank water injection in both
`reservoirs. Produced gas has been injected at the reser-
`voir’s crest forming a secondary gas cap. Development has
`taken place from a six-slot subsea template installed in
`1978 and a thirty-six slot platform installed in 1980. To
`date, 35 wells have been drilled consisting of twenty oil
`producers, fourteen water injectors, and one gas injector.
`Production at Fulmar plateaued at 165 KBD in 1983 and
`came off plateau in 1990. At the time of the 1992 seismic
`survey acquisition, production was 104 KBD with a 30%
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`ION 1012
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`Time-lapse analysis of the North Sea Fulmar Field
`
`water cut. Currently the water cut is over 90 %. The oil-
`water column has decreased from 900 feet to less than 100
`feet. Potential infill opportunities at Fulmar have moti-
`vated the time-lapse seismic study.
`
`Seismic Data
`
`Two 3-D seismic surveys have been acquired over Fulmar.
`The I977 pre-production survey was shot using a single 48
`channel analog cable with a 25 m group spacing and a 75
`m crossline spacing. The source was a 2000 in3 airgun
`my. The survey was reprocessed in 1987 using an im-
`proved migration scheme and the bins were interpolated to
`a 25 x 25 m spacing. The second survey was acquired in
`1992 to help identify infill targets. A 3470 in3 airgun ar-
`ray was used with triple 3000 m streamers resulting in 30
`fold coverage and 12.5 x 12.5 m bin spacing.
`
`The two surveys have comparable data quality as shown in
`Figure 2. While not laterally extensive on the seismic
`throughout the reservoir, the original oil-water contact is
`quite prominent on the line illustrated in Figure 2. The
`OOWC occurs at about 3.060 sec. and is, in part, the result
`of preserved porosity in the original oil leg. Although the
`contact has moved over 500 feet, a flat reflection event
`remains on the 1992 survey albeit somewhat broken up.
`Reflection amplitudes within the reservoir interval change
`between the two surveys. However, a trace-to-trace com-
`parison is difficult because the two surveys were migrated
`using different velocities.
`
`In order to robustly difference the seismic data, the meth-
`odology illustrated in Figure 3 was used. The key step is
`inversion of the data using a model-based algorithm which
`equalizes the two surveys by removing the seismic wavelet.
`The resulting 3-D impedance models were then averaged
`between the top of the Fulmar Formation (the Rihble is
`excluded from the time-lapse analysis) and the position of
`the OOWC. Averaging increases the signal-to-noise of the
`seismic difference at the expense of vertical resolution.
`The methodology was tested by differencing the average
`impedance calculated for the Cretaceous chalk which un-
`conformably overlies the field. Presumably there should
`be no change in the chalk’s impedance between 1977 and
`1992. Over a majority of the survey area the method re-
`sults in changes of only 2% or less.
`
`Figure 4 illustrates the change in average impedance for the
`main Fulmar reservoir between I977 and 1992. Increases
`in impedance are observed along the western and southern
`flanks of the reservoir. No change or even a decrease in
`impedance is seen at the reservoir’s structural crest.
`
`1 9 7 7 S u r v e y
`
`1 9 9 2 S u r v e y
`
`Figure 2. Comparison of 1977 baseline seismic survey and the 1992 repeat survey.
`
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`Time-lapse analysis of the North Sea Fulmar Field
`
`According to the flow model, gas saturation increases of
`over 90% occur in a limited area at the structural crest.
`The pressure decline of 1000 psi is relatively uniform
`across the field although there is approximately a 150 psi
`greater reduction at the crest compared to the field’s flanks.
`
`SW-NE Cross Section
`
`Flow Simulation
`
`The flow simulation model for the Fulmar Field was origi-
`nally developed by Exxon in 1991 and is currently
`stewarded by Esso Exploration and Production UK. The
`32,736 grid block model (32 x 33 x 31) is fully history
`matched to include production, individual well pressures,
`and fluid contact movements. To compare to time-lapse
`seismic behavior, two time steps were extracted from the
`model, one at the beginning of production in January 1982,
`and the other at the time of the acquistion of the second
`survey in April 1992. Figure 5 illustrates water saturation
`changes calculated between the two simulation time steps.
`Saturation increases as high as 65% are seen. In map view
`the saturation changes look similar to the seismic changes
`shown in Figure 4.
`
`Figure 4. Change in Fulmar reservoir impedance between
`1977 and 1992.
`
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`Figure 5. Water saturation changes between two flow
`simulation time steps, one at the beginning of produc-
`fion, the other in 1992.
`
`Petrophysics
`
`Gassmann fluid substitution calculations suggest a 4 to 5%
`increase in impedance as a result of water displacing oil at
`the saturations predicted by the flow simulation. A 4%
`decrease in impedance is expected as a result of secondary
`gas cap formation. No core measurements are available to
`directly determine the effect of pressure decline on imped-
`ance. However, as reported by Watts et al. (1996), a
`pressure decline of about 2000 psi in Upper Jurrasic sands
`at the Magnus Field results in an impedance increase of
`12%. Well log data at Fulmar suggest an even greater
`pressure effect on impedance but these data are influenced
`by compaction and diagenesis. As a result, we conclude
`that pressure changes probably have a greater impact on
`impedance changes than do fluid saturation effects. At the
`crest of the reservoir, pressure decline is expected to
`counter the effect of gas cap formation on the impedance.
`
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`Time-lapse analysis of the North Sea Fulmar Field
`
`Comparison to Model
`
`Conclusions
`
`Using petrophysical relationships derived from well logs
`and fluid substitution from Gassmann’s equation, we can
`estimate the average reservoir impedance changes from the
`flow simulation model. This predicted impedance change
`is illustrated in Figure 6. There is general agreement with
`the measured impedance changes shown in Figure 4 sug-
`gesting that the observed changes are associated with water
`influx and pressure decline.
`
`Areas that are predicted to have changed from the model
`but have not changed in the data may represent bypassed
`oil. One such example is the area in the southwest comer
`of the field. Other potential bypassed areas may occur near
`faults. However, the seismic data quality is not sufficient
`to serve as the sole basis for drilling decisions. Many of
`the smaller-scale features seen on the data may be influ-
`enced by artifacts such as fault shadowing, unrelated to
`production changes. Had the field tapes for the 1977 sur-
`vey been available, pre- and/or post-stack reprocessing of
`the data to improve repeatability would have been advanta-
`geous.
`
`Seismic differences at Fulmar are related to saturation and
`pressure changes. The interpretation of impedance changes
`in terms of potential bypassed areas requires integration
`with the reservoir flow model. However, the data quality is
`not sufficient to conclusively demonstrate that small-scale
`features on the seismic difference map are related to pro-
`duction processes.
`
`Acknowledgements
`
`We thank Esso Exploration and Production, U.K. and Shell
`U.K. Exploration and Production for permission to present
`this paper.
`
`Reference:
`
`Watts, G. F. T., D. Jizba, D. E. Gawith, and P. Guttcridge,
`1996, Reservoir monitoring of the Magnus Field
`through 4D time-lapse seismic analysis: Petroleum
`Geoscience, v. 2, pp 361-372.
`
`Figure 6. Calculated impedance changes from the reser-
`voir flow simulation.
`
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`This article has been cited by:
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`1. Partha Routh, Gopal Palacharla, Ivan Chikichev, Spyros LazaratosFull Wavefield Inversion of Time-Lapse Data for Improved
`Imaging and Reservoir Characterization 1-6. [Abstract] [References] [PDF] [PDF w/Links]
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